System for upgrading residuum hydrocarbons

ABSTRACT

A process for upgrading residuum hydrocarbons is disclosed. The process may include: contacting a residuum hydrocarbon fraction and hydrogen with a first hydroconversion catalyst in a first ebullated bed hydroconversion reactor system; recovering a first effluent from the first ebullated bed hydroconversion reactor system; solvent deasphalting a vacuum residuum fraction to produce a deasphalted oil fraction and an asphalt fraction; contacting the deasphalted oil fraction and hydrogen with a second hydroconversion catalyst in a second hydroconversion reactor system; recovering a second effluent from the second hydroconversion reactor system; and fractionating the first effluent from the first ebullated bed hydroconversion reactor system and the second effluent from the second hydroconversion reactor system to recover one or more hydrocarbon fractions and the vacuum residuum fraction in a common fractionation system.

FIELD OF THE DISCLOSURE

Embodiments disclosed herein relate generally to hydroconversionprocesses, including processes for hydrocracking residue and other heavyhydrocarbon fractions. More specifically, embodiments disclosed hereinrelate to hydrocracking of a residuum hydrocarbon feedstock, solventdeasphalting of the unconverted residuum hydrocarbon feedstock,processing the resulting hydrocracked deasphalted oil in a separateresidue hydrocracking unit, and processing the pitch from the solventdeasphalting unit in a separate residue hydrocracking unit.

BACKGROUND

As the worldwide demand for gasoline and other light refinery productshas steadily increased, there has been a significant trend towardconversion of higher boiling compounds to lower boiling ones. To meetthe increasing demand for distillate fuels increased, refiners haveinvestigated various reactors, such as hydrocracking reactors, residualdesulfurization units (RDS), and solvent deasphalting (SDA) units, toconvert Residuum, Vacuum Gas Oil (VGO) and other heavy petroleumfeedstocks to jet and diesel fuels.

Catalysts have been developed that exhibited excellent distillateselectivity, reasonable conversion activity and stability for heavierfeedstocks. The conversion rates attainable by the various processes arelimited, however. For example, RDS units alone can produce a 1 wt %sulfur fuel from high sulfur residua, but conversions are generallylimited to about 35% to 40%, Others have proposed to use SDA units tosolvent deasphalt the residuum feed and process the deasphalted oil onlyin a Residuum Hydrocracking Unit (RHU). Also, others have processed theunconverted vacuum residuum from a RHU in an SDA unit and recycled thedeasphalted oil (DAO) back to the front end of the RHU. Still othershave proposed to process the SDA pitch directly in a RHU. Nonetheless,economic processes to achieve high hydrocarbon conversions and sulfurremoval are desired.

SUMMARY

In one aspect, embodiments disclosed herein relate to a process forupgrading residuum hydrocarbons. The process may include the followingsteps: contacting a residuum hydrocarbon fraction and hydrogen with afirst hydroconversion catalyst in a first ebullated bed hydroconversionreactor system; recovering a first effluent from the first ebullated bedhydroconversion reactor system; solvent deasphalting a vacuum residuumfraction to produce a deasphalted oil fraction and an asphalt fraction;contacting the deasphalted oil fraction and hydrogen with a secondhydroconversion catalyst in a second hydroconversion reactor system;recovering a second effluent from the second hydroconversion reactorsystem; and fractionating the first effluent from the first ebullatedbed hydroconversion reactor system and the second effluent from thesecond hydroconversion reactor system to recover one or more hydrocarbonfractions and the vacuum residuum fraction in a common fractionationsystem.

In another aspect, embodiments disclosed herein relate to a system forupgrading residuum hydrocarbons. The system may include the following: afirst ebullated bed hydroconversion reactor system for contacting aresiduum hydrocarbon fraction and hydrogen with a first hydroconversioncatalyst to produce a first effluent; a solvent deasphalting unit tosolvent deasphalt a vacuum residuum fraction to produce a deasphaltedoil fraction and an asphalt fraction; a second hydroconversion reactorsystem for contacting the deasphalted oil fraction and hydrogen with asecond hydroconversion catalyst to produce a second effluent; and afractionation unit to fractionate the first effluent and the secondeffluent to recover one or more hydrocarbon fractions and the vacuumresiduum fraction.

In another aspect, embodiments disclosed herein relate to a system forupgrading residuum hydrocarbons. The system may include the following: afirst ebullated bed hydroconversion reactor system for contacting aresiduum hydrocarbon fraction and hydrogen with a first hydroconversioncatalyst to produce a first effluent; a solvent deasphalting unit tosolvent deasphalt a vacuum residuum fraction to produce a deasphaltedoil fraction and an asphalt fraction; a second hydroconversion reactorsystem for contacting the deasphalted oil fraction and hydrogen with asecond hydroconversion catalyst to produce a second effluent; and aseparator to separate a combined fraction of the first effluent and thesecond effluent to recover a liquid fraction and a vapor fraction; afractionation unit to fractionate the liquid to recover the vacuumresiduum fraction; a third hydroconversion reactor system for contactingthe vapor fraction with a third hydroconversion catalyst to produce athird effluent; and a fractionation unit to fractionate the thirdeffluent to recover one or more hydrocarbon fractions.

In another aspect, embodiments disclosed herein relate to a system forupgrading residuum hydrocarbons. The system may include the following: afirst ebullated bed hydroconversion reactor system for contacting aresiduum hydrocarbon fraction and hydrogen with a first hydroconversioncatalyst to produce a first effluent; a solvent deasphalting unit tosolvent deasphalt a vacuum residuum fraction to produce a deasphaltedoil fraction and an asphalt fraction; a second hydroconversion reactorsystem for contacting the deasphalted oil fraction and hydrogen with asecond hydroconversion catalyst to produce a second effluent; and afirst fractionation unit to fractionate the first effluent and thesecond effluent to recover one or more hydrocarbon fractions and thevacuum residuum fraction; a third ebullated bed hydroconversion reactorsystem for contacting the asphalt fraction and hydrogen to produce thirdeffluent; a separator to separate the third effluent and recover aliquid fraction and a vapor fraction; a second fractionation unit tofractionate the liquid to recover the vacuum residuum fraction; a fourthhydroconversion reactor system for contacting the vapor fraction with afourth hydroconversion catalyst to produce a fourth effluent; and athird fractionation unit to fractionate the fourth effluent to recoverone or more hydrocarbon fractions.

Other aspects and advantages will be apparent from the followingdescription and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a simplified process flow diagram of a process for upgradingresiduum hydrocarbon feedstocks according to embodiments disclosedherein.

FIG. 2 is a simplified process flow diagram of a process for anintegrated hydroprocessing reactor system to be used with a process forupgrading residuum hydrocarbon feedstocks according to embodimentsdisclosed herein.

FIG. 3 is a simplified alternate process flow diagram of a process foran integrated hydroprocessing reactor system to be used with a processfor upgrading residuum hydrocarbon feedstocks according to embodimentsdisclosed herein.

DETAILED DESCRIPTION

In one aspect, embodiments herein relate generally to hydroconversionprocesses, including processes for hydrocracking residue and other heavyhydrocarbon fractions. More specifically, embodiments disclosed hereinrelate to hydrocracking of a residuum hydrocarbon feedstock, solventdeasphalting of the unconverted residuum hydrocarbon feedstock,processing the resulting hydrocracked deasphalted oil in a separateresidue hydrocracking unit, and processing the pitch from the solventdeasphalting in a separate residue hydrocracking unit.

Hydroconversion processes disclosed herein may be used for reactingresiduum hydrocarbon feedstocks at conditions of elevated temperaturesand pressures in the presence of hydrogen and one or morehydroconversion catalyst to convert the feedstock to lower molecularweight products with reduced contaminant (such as sulfur and/ornitrogen) levels. Hydroconversion processes may include, for example,hydrogenation, desulfurization, denitrogenation, cracking, conversion,demetallization, and removal of metals, Conradson Carbon Residue (CCR)or asphaltenes removal, etc.

As used herein, residuum hydrocarbon fractions, or like terms referringto residuum hydrocarbons, are defined as a hydrocarbon fraction havingboiling points or a boiling range above about 340° C. but could alsoinclude whole heavy crude processing. Residuum hydrocarbon feedstocksthat may be used with processes disclosed herein may include variousrefinery and other hydrocarbon streams such as petroleum atmospheric orvacuum residua, deasphalted oils, deasphalter pitch, hydrocrackedatmospheric tower or vacuum tower bottoms, straight run vacuum gas oils,hydrocracked vacuum gas oils, fluid catalytically cracked (FCC) slurryoils, vacuum gas oils from an ebullated bed hydrocracking process,shale-derived oils, coal-derived oils, tar sands bitumen, tall oils,bio-derived crude oils, black oils, as well as other similar hydrocarbonstreams, or a combination of these, each of which may be straight run,process derived, hydrocracked, partially desulfurized, and/or partiallydemetallized streams. In some embodiments, residuum hydrocarbonfractions may include hydrocarbons having a normal boiling point of atleast 480° C., at least 524° C., or at least 565° C.

Referring now to FIG. 1, a residuum hydrocarbon fraction (residuum) 10and hydrogen 21 may be fed to an ebullated bed reactor system 42, whichmay include one or more ebullated bed reactors arranged in series orparallel, where the hydrocarbons and hydrogen are contacted with ahydroconversion catalyst to react at least a portion of the residuumwith hydrogen to form lighter hydrocarbons, demetallize the metalscontained in residuum, remove Conradson Carbon Residue, or otherwiseconvert the residuum to useful products.

Reactors in ebullated bed reactor 42 may be operated at temperatures inthe range from about 380° C. to about 450° C., hydrogen partialpressures in the range from about 70 bara to about 170 bara, and liquidhourly space velocities (LHSV) in the range from about 0.2 h⁻¹ to about2.0 h⁻¹. Within the ebullated bed reactors, the catalyst may be backmixed and maintained in random motion by the recirculation of the liquidproduct. This may be accomplished by first separating the recirculatedoil from the gaseous products. The oil may then be recirculated by meansof an external pump, or, as illustrated, by a pump having an impellermounted in the bottom head of the reactor.

Target conversions in ebullated bed reactor system 42 may be in therange from about 30 wt % to about 75 wt %, depending upon the feedstockbeing processed. In any event, target conversions should be maintainedbelow the level where sediment formation becomes excessive and therebyprevent continuity of operations. In addition to converting the residuumhydrocarbons to lighter hydrocarbons, sulfur removal may be in the rangefrom about 40 wt % to about 65 wt %, metals removal may be in the rangefrom about 40 wt % to 65 wt % and Conradson Carbon Residue (CCR) removalmay be in the range from about 30 wt % to about 60 wt %.

Reactor severity may be defined as the catalyst average temperature indegrees Fahrenheit of the catalysts loaded in the one or more ebullatedbed hydrocracking reactors multiplied by the average hydrogen partialpressure of the ebullated bed hydrocracking reactors in Bar absolute anddivided by the LHSV in the ebullated bed hydrocracking reactors. Thereactor severity of the ebullated bed reactor system 42 may be in therange from about 105,000° F.-Bara-Hr to about 446,000° F.-Bara-Hr.

Following conversion in ebullated bed reactor system 42, the partiallyconverted hydrocarbons may be recovered via flow line 44 as a mixedvapor/liquid effluent and fed to a fractionation system 46 to recoverone or more hydrocarbon fractions. As illustrated, fractionation system46 may be used to recover an offgas 48 containing light hydrocarbongases and hydrogen sulfide (H₂S), a light naphtha fraction 50, a heavynaphtha fraction 52, a kerosene fraction 54, a diesel fraction 56, alight vacuum gas oil fraction 58, a heavy gas oil fraction 60, and avacuum residuum fraction 62. In some embodiments, vacuum residuumfraction 62 may be recycled for further processing, such as to a solventdeasphalting (SDA) unit 12, the ebullated bed reactor system 42, orother reaction units 70, 20 discussed below. When the vacuum residuumfraction 62 is sent to the SDA unit 12, a portion of the heavy gas oilfraction 60 may also be routed to the SDA unit 12.

Fractionation system 46 may include, for example, a high pressure hightemperature (HF/HT) separator to separate the effluent vapor from theeffluent liquids. The separated vapor may be routed through gas cooling,purification, and recycle gas compression, or may be first processedthrough an Integrated Hydroprocessing Reactor System (IHRS), which mayinclude one or more additional hydroconversion reactors, alone or incombination with external distillates and/or distillates generated inthe hydrocracking process, and thereafter routed for gas cooling,purification, and compression.

In some embodiments, the vacuum resid fraction 62 is fed to a SolventDeasphalting Unit (SDA) 12. In SDA 12, the vacuum residuum fraction 62is contacted with a solvent to selectively dissolve asphaltenes andsimilar hydrocarbons to produce a deasphalted oil (DAG) fraction 14 anda pitch fraction 15. In other embodiments, a portion of the heavy gasoil fraction 60 may also be fed to the SDA 12.

Solvent deasphalting may be performed in the SDA 12, for example, bycontacting the residuum hydrocarbon feed with a light hydrocarbonsolvent at temperatures in the range from about 38° C. to about 204° C.and pressures in the range from about 7 Barg to about 70 barg Solventsuseful in the SDA 12 may include C3, C4, C5, C6 and/or C7 hydrocarbons,such as propane, butane, isobutene, pentane, isopentane, hexane,heptane, or mixtures thereof, for example. The use of the lighthydrocarbon solvents may provide a high lift (high DAO yield). In someembodiments, the DAO fraction 14 recovered from the SDA unit 12 maycontain 500 wppm to 5000 wppm asphaltenes heptane insoluble), 50 to 150wppm metals (such as Ni, V, and others), and 5 wt % to 15 wt % ConradsonCarbon Residue (CCR).

The DAO fraction 14 and hydrogen 23 may be fed to a hydrocrackingreactor system 20, which may include one or more hydrocracking reactors,arranged in series or parallel. In reactor system 20, the DAO fraction14 may be hydrocracked under hydrogen partial pressures in the rangefrom about 70 bara to about 180 bara, temperatures in the range fromabout 390° C. to about 460° C., and LHSV in the range from about 0.1 h⁻¹to about 2.0 h⁻¹ in the presence of a catalyst. In some embodiments,operating conditions in hydrocracking reactor system 20 may be similarto those described above for ebullated bed reactor system 42. In otherembodiments, such as where hydrocracking reactor system 20 includes oneor more ebullated bed reactors, the ebullated bed reactors may beoperated at higher severity conditions than those in reactor system 42,higher severity referring to a higher temperature, a higher pressure, alower space velocity or combinations thereof.

Depending on the vacuum residuum feedstock properties, the extent towhich metals and Conradson Carbon Residue are removed in the ebullatedbed reactor system 42, and the SDA solvent used, the DAO recovered maybe treated in a fixed bed reaction system or an ebullated bed reactorsystem 20, as illustrated, which may be similar to that described abovefor ebullated bed reactor system 42 with respect to gas/liquidseparations and catalyst recirculation, among other similarities. Afixed bed reactor system may be used, for example, where the metals andConradson Carbon. Residue content of the DAO is less than 80 wppm and 10wt %, respectively, such as less than 50 wppm ad 7 wt %, respectively.An ebullated bed reactor system may be used, for example, when themetals and Conradson Carbon Residue contents are higher than thoselisted above for the fixed bed reactor system. In either hydrocrackingreactor system 20, the number of reactors used may depend on the chargerate, the overall target residue conversion level, and the level ofconversion attained in ebullated bed reactor system 42, among othervariables. In some embodiments, one or two hydrocracking reactors may beused in hydrocracking reactor system 20. For an ebullated bed reactorsystem 20, the reactor severity may be in the range from about 215,000°F.-Bara-Hr to about 755,000° F.-Bara-Hr.

Following conversion in hydrocracking reactor system 20, the partiallyconverted hydrocarbons may be recovered via flow line 25 as a mixedvapor/liquid effluent and fed to the fractionation system 46 to recoverone or more hydrocarbon fractions as described above.

The pitch fraction 15 and hydrogen 16 may be fed to an ebullated bedreactor system 70, which may include one or more ebullated bed reactors,where the hydrocarbons and hydrogen are contacted with a hydroconversioncatalyst to react at least a portion of the pitch with hydrogen to formlighter hydrocarbons, demetallize the pitch hydrocarbons, removeConradson Carbon Residue, or otherwise convert the pitch to usefulproducts. In some embodiments, a portion of the residuum hydrocarbonfraction 10 may also be fed to the ebullated bed reactor system 70. Theratio of the residuum hydrocarbon fraction 10 in the ebullated bedreactor system 70 to the ebullated bed reactor system 42 may range fromabout 0.1/1 to about 10/1. In other embodiments, the ratio of theresiduum hydrocarbon fraction 10 in the ebullated bed reactor system 70to the ebullated bed reactor system 42 may be about 1/1.

The fixed-bed hydrotreating reactors 66 or 166 may containhydroprocessing catalysts tailored to hydrotreating reactions such ashydrodesulfurization, hydrodenitrogenation, olefins saturation,hydrodeoxygenation and hydrodearomatization. Alternatively, thefixed-bed hydrotreating reactors 66 or 166 can contain hydroprocessingcatalysts tailored to hydrocracking reactions. In other embodiments, thefixed-bed hydrotreating reactors 66 or 166 can contain a mixture ofhydrotreating catalysts and hydrocracking catalysts. Examples ofcatalysts which may be utilized, but are not limited to, may be found inU.S. Pat. No. 4,990,243; U.S. Pat. No. 5,215,955; and U.S. Pat. No.5,177,047, all of which are hereby incorporated by reference in theirentirety. In some embodiments, the fixed-bed hydrotreating reactors 66or 166 may not provide any demetallization and demetallization catalystsmay not be necessary.

Reactors in the ebullated bed reactor system 70 may be operated attemperatures in the range from about 380° C. to about 450° C., hydrogenpartial pressures in the range from about 90 bara to about 170 bara, andliquid hourly space velocities (LHSV) in the range from about 0.15 h⁻¹to about 2.0 h⁻¹. Within the ebullated bed reactors, the catalyst may beback mixed and maintained in random motion by the recirculation of theliquid product. This may be accomplished by first separating therecirculated oil from the gaseous products. The oil may then berecirculated by means of an external pump, or, as illustrated, by a pumphaving an impeller mounted in the bottom head of the reactor.

Target conversions in the ebullated bed reactor system 70 may be in therange from about 30 wt % to about 75 wt %, depending upon the feedstockbeing processed. In any event, target conversions should be maintainedbelow the level where sediment formation becomes excessive and therebyprevent continuity of operations. In addition to converting the residuumhydrocarbons to lighter hydrocarbons, sulfur removal may be in the rangefrom about 40 wt % to about 65 wt %, metals removal may be in the rangefrom about 40 wt % to 65 wt % and Conradson Carbon Residue (CCR) removalmay be in the range from about 30 wt % to about 60 wt %.

The reactor severity of the ebullated bed reactor system 70 may be inthe range from about 255,000° F.-Bara-Hr to about 880,000° F.-Bara-Hr.

Following conversion in the ebullated bed reactor system 70, thepartially converted hydrocarbons may be recovered via flow line 22 as amixed vapor/liquid effluent and fed to a fractionation system 24 torecover one or more hydrocarbon fractions. As illustrated, fractionationsystem 24 may be used to recover an offgas 26, a light naphtha fraction28, a heavy naphtha fraction 30, a kerosene fraction 32, a dieselfraction 34, a light vacuum gas oil fraction 36, a heavy gas oilfraction 38, and a vacuum residuum fraction 40. In some embodiments,vacuum residuum fraction 40 may be recycled for further processing. Inother embodiments, vacuum residuum fraction 40 may be blended with acutter fraction 64 to produce fuel oil. In some embodiments, the fueloil may have a sulfur content of less than about 1.5 weight percent.

Fractionation system 24 may include, for example, a high pressure hightemperature (HP/HT) separator to separate the effluent vapor from theeffluent liquids. The separated vapor may be routed through gas cooling,purification, and recycle gas compression, or may be first processedthrough an integrated Hydroprocessing Reactor System, alone or incombination with external distillates and/or distillates generated inthe hydrocracking process and thereafter routed for gas cooling,purification, and compression.

The separated liquid from the HP/HT separator may be flashed and routedto an atmospheric distillation system along with other distillateproducts recovered from the gas cooling and purification section. Theatmospheric tower bottoms, such as hydrocarbons having an initialboiling point of at least about 340° C., such as an initial boilingpoint in the range from about 340° C. to about 427° C., may then befurther processed through a vacuum distillation system to recover vacuumdistillates.

The vacuum tower bottoms product, such as hydrocarbons having an initialboiling point of at least about 480° C., such as an initial boilingpoint in the range from about 480° C. to about 565° C., may then berouted to tankage after cooling, such as by direct heat exchange ordirect injection of a portion of the residuum hydrocarbon feed into thevacuum tower bottoms product.

Catalysts useful in the ebullated bed reactors or hydrocracking reactorsmay include any catalyst useful in the hydroconversion processes ofhydrotreating or hydrocracking a hydrocarbon feedstock. A hydrotreatingcatalyst, for example, may include any catalyst composition that may beused to catalyze the hydrogenation of hydrocarbon feedstocks to increaseits hydrogen content and/or remove heteroatom contaminants. Ahydrocracking catalyst, for example, may include any catalystcomposition that may be used to catalyze the addition of hydrogen tolarge or complex hydrocarbon molecules as well as the cracking of themolecules to obtain smaller, lower molecular weight molecules.

In some embodiments, the effluents from the hydrocracking reactor system20, the ebullated bed reactor system 42, or the ebullated bed reactorsystem 70 may be processed prior to entering the fractionation system 24or the fractionation system 46 through an Integrated HydroprocessingReactor System (IHRS). The IHRS is an inline fixed-bed hydrotreatingsystem utilizing an upstream high pressure/high temperature vapor/liquid(HP/HT V/L) separator located between the ebullated-bed hydroprocessingreactor and the downstream IHRS. The separator allows for a separationbetween the unconverted residuum in the liquid effluent of the HP/HT V/Lseparator and the overhead vapor products boiling below about 1000° F.normal boiling point which may provide a lower cost route for furtherhydrotreating or hydrocracking of the gas oils, diesel and naphthafractions formed by cracking of residuum in the upstream ebullated bedreactor.

The separated liquid from the HP/HT separator may be flashed and routedto an atmospheric distillation system along with other distillateproducts recovered from the gas cooling and purification section. Theatmospheric tower bottoms, such as hydrocarbons having an initialboiling point of at least about 340° C., such as an initial boilingpoint in the range from about 340° C. to about 427° C., may then befurther processed through a vacuum distillation system to recover vacuumdistillates.

The vacuum tower bottoms product, such as hydrocarbons having an initialboiling point of at least about 480° C., such as an initial boilingpoint in the range from about 480° C. to about 565° C., may then berouted to tankage after cooling, such as by direct heat exchange ordirect injection of a portion of the residuum hydrocarbon feed into thevacuum tower bottoms product.

FIGS. 2 and 3 illustrate two embodiments for the IHRS and are describedbelow, however other embodiments will be obvious to those skilled in theart as being possible. FIG. 2 illustrates an embodiment where the IHRSis installed downstream of the blended stream derived by mixing thepartially converted hydrocarbons recovered via flow line 44 fromebullated bed reactor system 42 and the partially converted hydrocarbonsrecovered via flow line 25 from the hydrocracking reactor system 20,FIG. 3 illustrates an embodiment where the IHRS is installed downstreamof the ebullated bed hydroprocessing reactor 70.

As shown in FIG. 2, the effluent streams 44 and 25 from ebullated bedhydroprocessing reactor 42 and the hydrocracking reactor system 20,respectively, may be cooled in a heat exchanger (not shown) and fed to aHP/HT V/L separator 61 where a vapor stream including the light productsand distillates boiling below about 1000° F. normal boiling point and aliquid stream including unconverted residuum may be separated andprocessed separately in downstream equipment. A vapor stream 67 may befed to a fixed-bed hydroprocessing reactor 66 to carry outhydrotreating, hydrocracking or a combination thereof. An effluentstream 68 from the MRS fixed-bed reactor system 66 is fed to thefractionation system 46 which recovers an offgas stream 48, lighthydrotreated or hydrocracked naphtha stream 50, heavy hydrotreated orhydrocracked naphtha stream 52, hydrotreated or hydrocracked kerosenestream 54, hydrotreated or hydrocracked diesel stream 56, as describedabove. The liquid stream 63 may be cooled in a heat exchanger (notshown) and depressurized in a pressure letdown system (not shown) beforebeing fed to a vacuum fractionation system 72 which recovers a lighthydrotreated or hydrocracked VGO stream 58, a heavy hydrotreated orhydrocracked VGO stream 60 and an unconverted vacuum residuum stream 62.In some embodiments, the vacuum tower bottoms product stream, such ashydrocarbons having an initial boiling point of at least about 480° C.,such as an initial boiling point in the range from about 480° C. toabout 565° C., may be routed to tankage after cooling, such as by directheat exchange or direct injection of a portion of the residuumhydrocarbon feed into the vacuum tower bottoms product.

As shown in FIG. 3, the effluent stream 22 from the ebullated bedreactor system 70 may be cooled in a heat exchanger (not shown) and fedto a HP/FIT V/L separator 161 where a vapor stream including the lightproducts and distillates boiling below about 1000° F. normal boilingpoint and a liquid stream including unconverted residuum may beseparated and processed separately in downstream equipment. A vaporstream 167 is fed to a fixed-bed hydroprocessing reactor 166 to carryout hydrotreating, hydrocracking or a combination thereof. An effluentstream 168 from the IHRS fixed-bed reactor system 166 may be fed to anatmospheric fractionation system 146 which recovers an offgas stream 26,light hydrotreated or hydrocracked naphtha stream 28, heavy hydrotreatedor hydrocracked naphtha stream 30, hydrotreated or hydrocracked kerosenestream 32, hydrotreated or hydrocracked diesel stream 34. A liquidstream 163 is cooled in a heat exchanger (not shown) and depressurizedin a pressure letdown system (not shown) and may be fed to a vacuumfractionation system 172 which recovers a light hydrotreated carhydrocracked VGO stream 36, a heavy hydrotreated or hydrocracked VGOstream 38 and an unconverted vacuum residuum stream 40. In someembodiments, the vacuum tower bottoms product stream, such ashydrocarbons having an initial boiling point of at least about 480° C.,such as an initial boiling point in the range from about 480° C. toabout 565° C., may then be routed to tankage after cooling, such as bydirect heat exchange or direct injection of a portion of the residuumhydrocarbon feed into the vacuum tower bottoms product.

Hydroconversion catalyst compositions for use in the hydroconversionprocess according to embodiments disclosed herein are well known tothose skilled in the art and several are commercially available fromW.R. Grace & Co., Criterion Catalysts & Technologies, and Albemarle,among others. Suitable hydroconversion catalysts may include one or moreelements selected from Groups 4-12 of the Periodic Table of theElements. In some embodiments, hydroconversion catalysts according toembodiments disclosed herein may comprise, consist of, or consistessentially of one or more of nickel, cobalt, tungsten, molybdenum andcombinations thereof, either unsupported or supported on a poroussubstrate such as silica, alumina, titania, or combinations thereof. Assupplied from a manufacturer or as resulting from a regenerationprocess, the hydroconversion catalysts may be in the form of metaloxides, for example. In some embodiments, the hydroconversion catalystsmay be pre-sulfided and/or pre-conditioned prior to introduction to thehydrocracking reactor(s).

Distillate hydrotreating catalysts that may be useful include catalystselected from those elements known to provide catalytic hydrogenationactivity. At least one metal component selected from Group 840 elementsand/or from Group 6 elements is generally chosen. Group 6 elements mayinclude chromium, molybdenum and tungsten. Group 8-10 elements mayinclude iron, cobalt, nickel, ruthenium, rhodium, palladium, osmium,iridium and platinum. The amount(s) of hydrogenation component(s) in thecatalyst suitably range from about 0.5% to about 10% by weight of Group8-10 metal component(s) and from about 5% to about 25% by weight ofGroup 6 metal component(s), calculated as metal oxide(s) per 100 partsby weight of total catalyst, where the percentages by weight are basedon the weight of the catalyst before sulfiding. The hydrogenationcomponents in the catalyst may be in the oxidic and/or the sulphidicform. If a combination of at least a Group 6 and a Group 8 metalcomponent is present as (mixed) oxides, it will be subjected to asulfiding treatment prior to proper use in hydrocracking. In someembodiments, the catalyst comprises one or more components of nickeland/or cobalt and one or more components of molybdenum and/or tungstenor one or more components of platinum and/or palladium. Catalystscontaining nickel and molybdenum, nickel and tungsten, platinum and/orpalladium are useful.

Residue hydrotreating catalyst that may be useful include catalystsgenerally composed of a hydrogenation component, selected from Group 6elements (such as molybdenum and/or tungsten) and Group 840 elements(such as cobalt and/or nickel), or a mixture thereof, which may besupported on an alumina support. Phosphorous (Group 15) oxide isoptionally present as an active ingredient. A typical catalyst maycontain from 3 to 35 wt % hydrogenation components, with an aluminabinder. The catalyst pellets may range in size from 1/32 inch to ⅛ inch,and may be of a spherical, extruded, trilobate or quadrilobate shape. Insome embodiments, the feed passing through the catalyst zone contactsfirst a catalyst preselected for metals removal, though some sulfur,nitrogen and aromatics removal may also occur. Subsequent catalystlayers may be used for sulfur and nitrogen removal, though they wouldalso be expected to catalyze the removal of metals and/or crackingreactions. Catalyst layer(s) for demetallization, when present, maycomprise catalyst(s) having an average pore size ranging from 1.25 to225 Angstroms and a pore volume ranging from 0.5-1.1 cm³/g. Catalystlayer(s) for denitrogenation/desulfurization may comprise catalyst(s)having an average pore size ranging from 100 to 190 Angstroms with apore volume of 0.54.1 cm³/g. U.S. Pat. No. 4,990,243 describes ahydrotreating catalyst having a pore size of at least about 60Angstroms, and preferably from about 75 Angstroms to about 120Angstroms. A demetallization catalyst useful for the present process isdescribed, for example, in U.S. Pat. No. 4,976,848, the entiredisclosure of which is incorporated herein by reference for allpurposes. Likewise, catalysts useful for desulfurization of heavystreams are described, for example, in U.S. Pat. Nos. 5,215,955 and5,177,047, the entire disclosures of which are incorporated herein byreference for all purposes. Catalysts useful for desulfurization ofmiddle distillate, vacuum gas oil streams and naphtha streams aredescribed, for example, in U.S. Pat. No. 4,990,243, the entiredisclosures of which are incorporated herein by reference for allpurposes.

Useful residue hydrotreating catalysts include catalysts having a porousrefractory base made up of alumina, silica, phosphorous, or variouscombinations of these. One or more types of catalysts may be used asresidue hydrotreating catalyst, and where two or more catalysts areused, the catalysts may be present in the reactor zone as layers. Thecatalysts in the lower layer(s) may have good demetallization activity.The catalysts may also have hydrogenation and desulfurization activity,and it may be advantageous to use large pore size catalysts to maximizethe removal of metals. Catalysts having these characteristics are notoptimal for the removal of Conradson Carbon Residue and sulfur. Theaverage pore size for catalyst in the lower layer or layers will usuallybe at least 60 Angstroms and in many cases will be considerably larger.The catalyst may contain a metal or combination of metals such asnickel, molybdenum, or cobalt. Catalysts useful in the lower layer orlayers are described in U.S. Pat. Nos. 5,071,805, 5,215,955, and5,472,928. For example, those catalysts as described in U.S. Pat. No.5,472,928 and having at least 20% of the pores in the range of 130 to170 Angstroms, based on the nitrogen method, may be useful in the lowercatalysts layer(s). The catalysts present in the upper layer or layersof the catalyst zone should have greater hydrogenation activity ascompared to catalysts in the lower layer or layers. Consequently,catalysts useful in the upper layer or layers may be characterized bysmaller pore sizes and greater Conradson Carbon Residue removal,denitrogenation and desulfurization activity. Typically, the catalystswill contain metals such as, for example, nickel, tungsten, andmolybdenum to enhance the hydrogenation activity. For example, thosecatalysts as described in U.S. Pat. No. 5,472,928 and having at least30% of the pores in the range of 95 to 135 Angstroms, based on thenitrogen method, may be useful in the upper catalysts layers. Thecatalysts may be shaped catalysts or spherical catalysts. In addition,dense, less friable catalysts may be used in the upflow fixed catalystzones to minimize breakage of the catalyst particles and the entrainmentof particulates in the product recovered from the reactor.

One skilled in the art will recognize that the various catalyst layersmay not be made up of only a single catalyst, but may be composed of anintermixture of different catalysts to achieve the optimal level ofmetals or Conradson Carbon Residue removal and desulfurization for thatlayer. Although some hydrogenation will occur in the lower portion ofthe zone, the removal of Conradson Carbon Residue, nitrogen, and sulfurmay take place primarily in the upper layer or layers. Obviouslyadditional metals removal also will take place. The specific catalyst orcatalyst mixture selected for each layer, the number of layers in thezone, the proportional volume in the bed of each layer, and the specifichydrotreating conditions selected will depend on the feedstock beingprocessed by the unit, the desired product to be recovered, as well ascommercial considerations such as cost of the catalyst. All of theseparameters are within the skill of a person engaged in the petroleumrefining industry and should not need further elaboration here.

While described above with respect to two separate fractionation systems24, 46, embodiments disclosed herein also contemplate fractionating theeffluents 22, 44, and 25 in a common fractionation system. For example,the effluents may be fed into a common gas cooling, purification, andcompression loop before further processing in an atmospheric tower and avacuum tower as described above. The use of a combined separation schememay provide for a reduced capital investment, when desired, but mayresult in the production of a single fuel oil fraction having a sulfurlevel intermediate those achieved by separate processing.

As described above, embodiments disclosed herein effectively processesvacuum residue and intermediate streams through multiple hydrocrackingreactors, each operating at different severities and processingdifferent feed compositions with a SDA located within the process,extending the residue conversion limits above those which can beattained by residue hydrocracking alone. Further, the higher conversionsmay be attained using less catalytic reactor volume as compared to otherschemes proposed to achieve similar conversions. As a result,embodiments disclosed herein may provide comparable or higherconversions but requiring a lower capital investment requirement.Further, embodiments disclosed herein may be used to produce a fuel oilhaving less than 1 wt % sulfur from a high sulfur containing residuefeed while maximizing overall conversion.

The overall processing schemes disclosed herein may be performed usinglow reactor volumes while still achieving high conversions. Likewise,other resulting advantages may include: reduced catalyst consumptionrates due to rejecting metals in the asphalt from the SDA unit; reducedcapital investment; and elimination or significant reduction in the needfor injection of slurry oil upstream of the ebullated bed reactors,among other advantages.

While the disclosure includes a limited number of embodiments, thoseskilled in the art, having benefit of this disclosure, will appreciatethat other embodiments may be devised which do not depart from the scopeof the present disclosure. Accordingly, the scope should be limited onlyby the attached claims.

What is claimed:
 1. A system for upgrading residuum hydrocarbons, thesystem comprising: a first ebullated bed hydroconversion reactor systemfor contacting a residuum hydrocarbon fraction and hydrogen to produce afirst effluent; a second ebullated bed hydroconversion reactor systemfor contacting a deasphalted oil fraction and hydrogen to produce asecond effluent; and a first fractionation unit to fractionate the firsteffluent and the second effluent to recover one or more hydrocarbonfractions comprising a vacuum residuum fraction; a solvent deasphaltingunit to solvent deasphalt the vacuum residuum fraction to produce thedeasphalted oil fraction and an asphalt fraction; a third ebullated bedhydroconversion reactor system for contacting the asphalt fraction andhydrogen to produce a third effluent; and a second fractionation unit tofractionate the third effluent to recover one or more hydrocarbonfractions.
 2. The system of claim 1, wherein the fractionation unit isfluidly coupled to at least one of the solvent deasphalting unit, avacuum distillation system, the first ebullated bed hydroconversionreactor system, the second ebullated bed hydroconversion reactor system,and the third ebullated bed hydroconversion reactor system.
 3. Thesystem of claim 1, wherein the first ebullated bed hydroconversionreactor system, the second ebullated bed hydroconversion reactor system,and the third ebullated bed hydroconversion reactor system operate atdifferent severities.
 4. The system of claim 1, wherein the firstfractionation unit further comprises a high pressure-high temperatureseparator.
 5. The system of claim 1, wherein the first fractionationunit further produces a heavy gas oil fraction which is sent to thesolvent deasphalting unit.
 6. The system of claim 1, wherein the firstfractionation unit and the second fractionation unit are a single unit.7. A system for upgrading residuum hydrocarbons, the system comprising:a first ebullated bed hydroconversion reactor system for contacting aresiduum hydrocarbon fraction and hydrogen to produce a first effluent;a solvent deasphalting unit to solvent deasphalt a vacuum residuumfraction to produce a deasphalted oil fraction and an asphalt fraction;a second ebullated bed hydroconversion reactor system for contacting thedeasphalted oil fraction and hydrogen to produce a second effluent; anda separator to separate a combined fraction of the first effluent andthe second effluent to recover a liquid fraction and a vapor fraction; afirst fractionation unit to fractionate the liquid fraction to recoverthe vacuum residuum fraction; a fixed bed hydroconversion reactor systemfor contacting the vapor fraction to produce a third effluent; a secondfractionation unit to fractionate the third effluent to recover one ormore hydrocarbon fractions; a third ebullated bed hydroconversionreactor system for contacting the asphalt fraction and hydrogen toproduce a third effluent; and a third fractionation unit to fractionatethe third effluent to recover one or more hydrocarbon fractions.
 8. Thesystem of claim 10, wherein the first fractionation unit is a vacuumdistillation unit.
 9. A system for upgrading residuum hydrocarbons, thesystem comprising: a first ebullated bed hydroconversion reactor systemfor contacting a residuum hydrocarbon fraction and hydrogen to produce afirst effluent; a solvent deasphalting unit to solvent deasphalt avacuum residuum fraction to produce a deasphalted oil fraction and anasphalt fraction; a second ebullated bed hydroconversion reactor systemfor contacting the deasphalted oil fraction and hydrogen to produce asecond effluent; and a first fractionation unit to fractionate the firsteffluent and the second effluent to recover one or more hydrocarbonfractions and the vacuum residuum fraction; a third ebullated bedhydroconversion reactor system for contacting the asphalt fraction andhydrogen to produce a third effluent; a separator to separate the thirdeffluent and recover a liquid fraction and a vapor fraction; a secondfractionation unit to fractionate the liquid traction to recover thevacuum residuum fraction; a fixed bed hydroconversion reactor system forcontacting the vapor fraction to produce a fourth effluent; and a thirdfractionation unit to fractionate the fourth effluent recover one ormore hydrocarbon fractions.
 10. The system of claim 12, wherein thesecond fractionation unit is an atmospheric distillation unit.
 11. Thesystem of claim 12, wherein the third fractionation unit is a vacuumdistillation unit.